PJM is considering five capacity import zones with a combined limit of 8,400 to 11,000 MW, officials told the Planning Committee Friday.
PJM’s initial review indicated the RTO could import 11,000 to 12,000 MW simultaneously. Last week, however, PJM’s Mark Sims told members that the limit will be “slightly lower” than 11,000 and closer to the 8,347 MWs imported on July 16, 2013, the highest import observed in an analysis of three years of historical data.
“It should be around [8,347 MW] or a little higher,” Sims said.
PJM officials said the MISO North zone should have been drawn to include the thumb of Michigan and NIPSCO on the PJM-MISO seam (Source: PJM Interconnection, LLC)
Officials said they are considering modeling five “conceptual import zones”: MISO; MISO North; TVA/Louisville Gas & Electric; VACAR and NYISO.
In response to members’ questions, officials also said they may add a sixth zone to reflect the integration of Entergy’s transmission system into MISO. Entergy is “two hops away” from PJM, said Sims. “I don’t think it will have that much of an impact on the final limit.”
Stu Bresler, PJM vice president of market operations, said PJM is unlikely to accept suggestions that imports have firm transmission before offering into the capacity auction. Bresler said officials fear that the Federal Energy Regulatory Commission would reject such a requirement, which would be analogous to requiring internal resources to have signed interconnection service agreements three years before the delivery year. That, Bresler said “would be a barrier to entry.”
The Planning Committee approved a problem statement on a proposed cap in response to the May Base Residual Auction, in which more than 7,400 MW of imports cleared.
PJM wants to include the new limit in February when it posts the planning parameters for the 2014 base auction.
To meet that schedule, officials plan to present proposed methodology and manual language at the Planning Committee meeting Nov. 7. The MRC will hear first reading on Nov. 14, with a vote scheduled for Nov. 21.
If imports hit the limit, officials said they will clear at lower prices than internal resources, just as resources east of PJM’s west-to-east constraints are often priced higher.
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Wilmington covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
2. PJM MANUALS (9:10-9:40)
Manual 3: Transmission Operations – Adds language regarding approval of emergency rating changes; added applicability for individual generators greater than 20 MVA; clarified reference to voltage coordination; revised outdated references.
Manual 10: Pre-Scheduling Operations – Annual Review. Minor updates for clarity; added references to forecasted planned outages and reporting outages on synchronous condensers.
Manual 14D: Generator Operational Requirements – Changes made at RFC request, and for consistency. Includes changes to reactive capability testing; replaces outdated references; requires generators operating or scheduled for PJM to operate to notify PJM prior to attempting a restart following a trip or failure to start.
Manual 14B: PJM Region Transmission Planning Process – Changes to improve the procedure for analyzing and addressing short circuits. PJM currently analyzes short circuit cases for the current year +1 and +5. System modifications are difficult for transmission owners to implement with a one-year lead time. The annual Regional Transmission Expansion Plan will analyze short circuit base cases for the current year +2.
3. GAS/ELECTRIC SENIOR TASK FORCE (GESTF) (9:40-10:10)
The committee will be asked to approve a proposed Problem Statement/Issue Charge to consider changing market rules to allow generators to reflect the cost of firm natural gas service and the timing of the Day-Ahead market clearing.
The potential changes will be evaluated by the Gas Electric Senior Task Force (GESTF), which was formed in March to study potential reliability problems resulting from PJM’s increasing reliability on gas-fired generation. (See previous coverage on gas-electric coordination.)
Under current rules, generators cannot reflect the cost of firm gas transportation in energy market offers. In addition, units must gas nominations before knowing whether they will be dispatched in the day-ahead market. Thus they may have to sell gas if their offer does not clear or derate during the morning peak if they don’t have enough gas.
Under the problem statement, the task force would consider potential changes to the timing of the day-ahead market clearing as well as rule changes that would allow offers to reflect firm gas costs and price changes between day-ahead commitments and real-time operation.
4. 2013 IRM STUDY (10:10-10:30)
The committee will be asked to endorse PJM staff’s recommendation to increase the Installed Reserve Margin (IRM) to 16.2% for delivery year 2014/15 (up from 15.9% in the 2012 analysis). The committee also will be asked to endorse margins of 15.7% for delivery years 2015 through 2018.
The increase, which was endorsed by the Planning Committee Oct. 10, is because of the increasing alignment of the RTO’s peak demand with demand outside of the region. (See Increased Installed Reserve Margin OKd for 2014)
Members Committee
2. CONSENT AGENDA (1:20-1:25)
B. Coordinated Transaction Scheduling
The Members Committee will be asked to approve Tariff and Operating Agreement changes to create the Coordinated Transaction Scheduling (CTS) product, designed to reduce uneconomic power flows between PJM and NYISO.
The new product would allow traders to submit “price differential” offers that would clear when the price difference between New York and PJM exceeds a threshold set by the bidder.
The Market Implementation Committee approved the product in September Coordinated Transaction Scheduling product after amending it to address member concerns about the reliability of PJM’s price projection algorithm, on which CTS trades will be based. The Markets and Reliability Committee approved the measure Sept. 26. (See New NYISO Product OKd)
C. Demand Response Registration Process
Members will be asked to approve Tariff and Operating Agreement revisions to simplify the process for registering demand response customers. The changes would remove or modify the role of load serving entities in the emergency and economic registration review process.
Members will be asked to approve increased penalties for under-performing Tier 2 synchronized reserve providers.
The MRC last month approved a proposal introduced by Dave Pratzon of GT Power Group after the Operating Committee selected it over a proposal from PJM and the Market Monitor. Pratzon said his proposal was tougher than the current penalty but less severe than the PJM-Market Monitor proposal, which he called overly punitive. (See OC Hears New Proposal on Synchronized Reserve Penalty; Delays Vote)
The Federal Energy Regulatory Commission last week approved a new reliability standard that will allow PJM and other transmission planners to plan for “non-consequential” load loss following a single contingency.
The rules, part of the North American Electric Reliability Corp.’s Transmission Planning Reliability Standard (TPL-001-4), includes limitations on the maximum amount of load that an entity may plan to shed, a stakeholder process and safeguards to ensure the rules are applied consistently. Use of such load losses “should be rare,” the commission said.
The new standard limits permissible non-consequential load losses to 75 MW. Planned load losses between 25 MW and 75 MW, or any planned loss at the 300 kV level or above would receive greater scrutiny by regulatory authorities and NERC.
In these cases, “the Transmission Planner or Planning Coordinator must ensure that applicable regulatory authorities or governing bodies responsible for retail electric service issues do not object to the use of” the load loss. Planners must also submit the information to NERC, which will determine whether there are any adverse reliability impacts from the plan.
The commission rejected a request from MISO that it define “regulatory authorities” that must be consulted. “Because each state and locality has different entities that are responsible for reliability of retail electric service, we are reluctant to further define who may participate,” the commission wrote.
The commission had rejected NERC’s previous attempts to write rules on the issue, saying they were too vague.
“I am pleased that we are putting behind us one of the most difficult outstanding issues dating from the commission’s March 2010 reliability orders,” Commissioner Cheryl LaFleur said in a statement. “This case was an example in which NERC and the industry proposed an `equally efficient and effective’ alternative solution to address a concern articulated by the commission.”
The Commission required NERC to submit a report based on the first two years of implementation of the new standard.
The new NERC standard also requires annual assessments addressing steady state, short circuit and stability conditions.
The Commission ordered NERC to make two changes to the standard. One modification will address concerns that it could exclude planned maintenance outages of significant facilities from planning assessments. The other will change the TPL-001-4, Requirement R1 Violation Risk Factor from medium to high.
Amid complaints that the issue has not been fully vetted, members of the Capacity Senior Task Force are voting on four proposals to cap the volume of limited demand response that can clear PJM’s base capacity auction. The vote, which was opened last week, closes today.
Katie Guerry, representing demand response aggregator EnerNOC Inc., said the vote should be delayed because changes being considered to increase DR’s flexibility may alleviate some of the concerns that prompted calls for caps. “We’re concerned that we’re putting the cart before the horse,” she told the task force at a meeting last week. “We’re not convinced there’s a problem.”
Walter Hall, of the Maryland Public Service Commission, and John Farber, of the Delaware Public Service Commission, supported Guerry’s call for a delay. Hall said Maryland would like more time to evaluate the impact of the proposed changes on demand response in the state before taking a position.
But PJM’s Scott Baker, chair of the task force, said the schedule was necessary to make changes by February, when the RTO must post planning parameters for the 2014 Base Residual Auction.
Boom-Bust Cycles
PJM says the current rules result in a vertical demand curve that leads to boom-bust cycles where the system “oscillates” between being long on capacity, with low prices, and being short on capacity with high prices.
Under current rules, 4.8% of PJM’s reliability requirement can be filled with limited demand response, with higher levels possible if excess capacity clears against the sloped Variable Resource Requirement (VRR) demand curve. PJM wants to reduce the 4.8% by all of the 2.5% Short-term Resource Procurement Target (STRPT) for a net of 2.3%.
An alternate proposal by Southern Maryland Electric Cooperative and consultant James Wilson on behalf of consumer advocates for Maryland, Delaware and New Jersey would reduce the 4.8% by only a portion — to be determined — of the 2.5% holdback. The proposal would increase the 4.8% base to recognize that DR will increasingly be used as an operational resource.
$1.8 Billion Cost Increase
PJM Proposed Method for Modeling of the Limited & Extended Summer Demand Response Targets (Source: PJM Interconnection, LLC)
PJM’s proposal would have increased total costs by more than $1.8 billion over actual costs for 2015/16 and 2016/17, an increase of 12%, according to a simulation by PJM. It would have reduced the volume of limited DR by 64%.
The SMECO/Public Advocates’ proposal would have increased costs by less than 1% over the two years while reducing the volume of limited DR by about one-fifth.
Wilson, who drafted the public advocates’ proposal, said he was pleased with the results of the analysis. “It allows annual and extended summer to compete to the VRR curve,” he said.
EnerNoc and EnergyConnect, another demand response aggregator, also submitted alternatives, but they came too late for PJM to conduct simulations.
EnerNOC’s proposal would re-institute sloped demand curves for Extended Summer, Annual and Limited DR products. It would use the minimum resource requirements for Annual and Extended Summer resources to create sloped demand curves for those products, in the same manner that the VRR curve is created. The auction would have to clear to the sloped curves instead of the vertical curves before resuming clearing in merit order for all products.
EnergyConnect’s proposal would adopt PJM’s proposal but differs on its handling of extended summer DR. It would continue the current rules capping Extended Summer DR at 10.5%. PJM wants to reduce that limit by the 2.5% holdback to a net of 8%.
The vote asks members whether they can support any of the four proposals and also includes a non-binding poll asking whether they would prefer to keep the status quo. The results will be presented at the Markets and Reliability Committee meeting Thursday.
DR as an Operational Resource
While the task force remained deeply split over the handling of limited DR, members seemed to be coming closer to consensus on two related issues — increasing DR’s flexibility and eliminating arbitrage opportunities between the Base and Incremental auctions — during the day-long meeting.
PJM’s Pete Langbein said the RTO has amended its proposal regarding a must-offer requirement for economic DR in response to stakeholder feedback. Langbein said PJM now wants to drop the must-offer requirement as long as it can dispatch DR with capacity commitments without declaring an emergency.
“These [changes] are really going in the right direction for us,” said Guerry.
Dispatch Time
Bruce Campbell, representing EnergyConnect, said a PJM proposal to require DR resources to prove they cannot be dispatched in 30 minutes could create an “unwieldy administrative construct.” He said proposals to pay quicker-responding DR resources more than slower ones will be sufficient to give PJM the resource diversity it seeks.
If 10% of the 15,000 DR resources seek such waivers, he said, it would result in 1,500 applications. “I think you risk losing a lot of demand response resources, at significant cost to load, if you continue going down this road,” he said.
But Stu Bresler, PJM vice president of market operations, noted that only 5% of DR has voluntarily chosen to be dispatched in one hour, with the remainder choosing two-hour dispatch. “My response to Bruce is, ‘How do I know I’m going to get that stratification?’”
Auction Arbitrage
Members reacted favorably to a new proposal by Gabel Associates to eliminate auction arbitrage opportunities.
PJM has proposed eliminating any profits that resources might receive from clearing at high prices in the BRA and buying out their position at a lower price in the incremental auction.
Gabel’s Michael Borgatti told the task force that PJM’s proposal provides little incentive to develop resources and may still result in resources failing to deliver.
Gabel’s proposal, made on behalf of RC Cape May Holdings, would reduce deficiency penalties for projects that pass development milestones evidencing good faith efforts to meet their commitments. Unlike PJM’s proposal, it would not apply the rules changes retroactively.
The Federal Energy Regulatory Commission has scheduled a technical conference for Nov. 13 to explore the implications of rule changes already proposed by PJM to address arbitrage concerns. The commission conditionally accepted proposed Tariff changes on Oct. 1 (Docket No. ER13-2108).
Delmarva Power & Light Co. must defend itself against challenges to its formula transmission rate filings for 2011 and 2012, the Federal Energy Regulatory Commission ruled last week.
FERC unanimously rejected Delmarva’s claim that the challenges by municipal power agencies and electric cooperatives were impermissible on procedural grounds, though the commission did narrow the issues to be litigated.
The commission ordered a hearing on whether Delmarva’s filings are consistent with FERC rules regarding accounting for income taxes and whether it properly allocated expenses from its parent, Pepco Holdings, Inc. It encouraged the parties — which include Delaware Municipal Electric Corporation, Inc. (DEMEC), Easton Utilities, Old Dominion Electric Cooperative and the Public Power Association of New Jersey — to settle the issues before the hearing.
DEMEC contends that Delmarva has added new costs that were not included in its initial formula rate and that the company improperly booked some non-transmission expenses. The protestors also complained about an increase in Delmarva’s administrative & general costs since implementation of the formula rate.
The commission rejected Delmarva’s contention that that the terms of a 2006 settlement (Baltimore Gas and Electric Co., 115 FERC 61,066) do not permit prudence challenges and that the formula rate inquiry is limited to whether costs were booked to the correct account.
“The commission’s acceptance of a formula rate constitutes acceptance of the formula, but not the inputs to the formula,” the commission wrote. “Parties can challenge the inputs to the formula rate in the same way as they can challenge costs in a stated rate case, including by raising prudence issues. In order for formula rates to work properly, they must allow for after-the-fact corrections and updates.”
The commission dismissed challenges to Delmarva’s handling of taxes associated with deferred investment tax credits and non-deductible pensions and other benefits.
FERC also rejected DEMEC’s request to reduce Delmarva’s return on equity, saying that it was outside the scope of issues permitted in challenges to annual rate filings. The panel noted that DEMEC and the Delaware Consumer Advocate’s office are contesting the ROE in a separate challenge before the commission (EL13-48).
The Federal Energy Regulatory Commission last week reiterated its 20 MW threshold regarding purchase obligations from qualifying facilities as the panel’s two Republican members said the commission should rethink its approach.
The commission ruled that PPL Electric Utilities Corp. must purchase excess power from a proposed 18.1 MW combined heat and power plant because the utility failed to prove the QF facility would have “nondiscriminatory” access to PJM’s wholesale markets.
The order reiterated the commission’s 2006 Order 688, in which it said that QFs above 20 MW were presumed to have access to the wholesale markets and those below were presumed to lack that access. For generators below 20 MW, FERC said, the burden of proof falls on the utility in whose territory the facility is located.
The commission said PPL failed to meet that threshold in its dispute with the IPS Power Engineering Inc. cogeneration facility at a beef processing plant in Souderton, Pa.
IPS Power Engineering Gas Turbine (Source: IPS Power Engineering)
JBS USA LLC, the meat processor, wants to team with IPS to control its power costs and ensure reliable supply. But the partners say the plant won’t be feasible without a contract to sell at least 10 years of its excess energy and capacity to PPL.
The commission ruled that PPL “attempted to make many of the same generalized showings” that the it rejected in its 2010 Public Service Co. of New Hampshire order (131 FERC ¶ 61,027). “Specifically, PPL Electric alleges that the Souderton QF has nondiscriminatory access to PJM’s markets because PJM’s market rules provide such access, and that the Souderton QF will neither have operational characteristics nor face constraints that would definitionally prevent access to PJM’s markets.”
The commission’s ruling could affect many other utilities within PJM. According to PPL, there are 150 generation projects below 20 MW in PJM’s interconnection queue.
The 1978 Public Utility Regulatory Policies Act (PURPA) requires electric utilities to purchase the output of cogeneration and small power production qualifying facilities at their “avoided costs.” The Energy Policy Act of 2005 amended PURPA to allow termination of QF requirements if FERC finds that the QF has nondiscriminatory access to make market sales.
The commission has never granted any utility relief from the mandatory purchase obligation for a QF of 20 MW or smaller. Nor has it given much guidance regarding what kind of evidence would convince it.
Order 688 said such evidence could include whether the QF has already participated in the market. PPL could not make that showing, the commission acknowledged, because the Souderton QF has not begun operation.
And that, said Commissioners Philip Moeller and Tony Clark, is a problem. Although they acknowledged the order follows FERC precedent they said the commission should provide more guidance.
“While we concur with the overall finding in this order and agree that PPL’s application lacked certain QF-specific information required under the Commission’s regulations, such as a system impact study for the interconnection, we do not agree that the PJM market rules and planning process are irrelevant for purposes of determining QF-specific market access,” they wrote.
They said the standard of proof shouldn’t be “so high as to preclude a utility from successfully making a showing before the QF is fully operational and the utility is obligated to purchase.”
Such a “circular result,” they said, could “[render] meaningless the opportunity to rebut the presumption and obtain PURPA relief.”
LAUREL, MD — As manager of a team of eight staffers charged with combating cybersecurity threats to the PJM grid, Stephen McElwee carries secrets.
Steven McElwee, PJM Manager, Corporate Information Security at the October meeting of the INCOSE Chesapeake Chapter
“If I run off to a security briefing, I learn a lot of things and I go home scared. But I can’t tell my analysts who are actually doing the real-time monitoring anything about it” because security clearances are limited to managers, he says.
Such is life in the cybersecurity world, McElwee, PJM manager of corporate information security, told an audience of more than 80 systems engineers at John Hopkins University Applied Physics Laboratory here. Most of the audience at the lecture, sponsored by the International Council on Systems Engineering (INCOSE), were contract workers for the nearby National Security Agency. (See video of lecture.)
“A year and a half ago I would have said [hackers] haven’t touched the energy sector. Now they are touching the energy sector,” he said. “It’s not a matter of if [PJM is attacked] but when.”
Threats to Pipelines, Smart Meters
McElwee said natural gas pipelines have been under attack since last year. “That campaign resulted in breaching of many natural gas companies — stealing plans, and gaining possible footholds in those companies.” Some hackers obtained plans for pipeline compressors.
McElwee and his colleagues also worry about botnets — private computers infected with malicious software and controlled as a group — taking control of thousands of smart meters. “You could … suddenly switch on and off that load, making it nearly impossible to control” the system, he said.
PJM Defenses
PJM’s defenses are a combination of risk assessment, education of system users and information-sharing partnerships with government and industry.
Education is key to prevent “spear phishing,” in which hackers penetrate networks through unwitting employees.
Thus, PJM hired a consultant to conduct mock phishing campaigns by sending employees emails with links that could have contained malware. When the test started, McElwee said, one in five recipients clicked the bad links. Over a year of education, the click-through rate was reduced to 4%, where it has remained in the current year. “It’s hard to get it below that” rate, he said.
PJM also has hired contractors to conduct penetration testing — probing the network for vulnerabilities — and to provide 24-hour monitoring of threats. It has staff dedicated to installing patches and has formed a security assessment committee of PJM officials to identify risks in any new software and projects.
`Kill Chains’
The company uses “kill chain” analyses to assess threats: “How far did it make it? Where did we stop it? Where did we detect it?”
PJM uses that data as an input back in its risk assessment, McElwee said, “so we have a feedback loop that allows us to continually improve our security posture.”
PJM relies on partnerships with industry and government to ensure it has adequate response plans and the best technology. “We recognize we can’t do this on our own,” McElwee said.
Cyber Risk Information Sharing Program (CRISP) (Source: PJM Interconnection, LLC)
Thus, PJM has become one of four pilot participants in the Cyber Risk Information Sharing Program (CRISP), a Department of Energy program involving Argonne National Laboratory, Pacific Northwest National Laboratory (PNNL), and the Electric Sector Information Sharing Analysis Center, a project of the North American Electric Reliability Corp. (NERC).
CRISP analyzes PJM’s network traffic and uses “snort signatures” and other techniques to identify potential threats.
“When there’s something suspicious that they see on our network they give us a call and say `here’s an IP address you need to block’ and we can proceed and block that address and never know it was the nation-state of the day that was attacking us,” McElwee said. “All we know is that somebody was watching out for us.”
CRISP is considering adding 20 new participants soon, with a broader expansion after that. “Because the power grid isn’t just PJM,” McElwee said. “It’s all the transmission owners all the generation owners that make up the entire system.”
NERC Standards ‘Dated’
McElwee said NERC’s Critical Infrastructure Protection standards are “dated.” A new version, which is awaiting final approval by the Federal Energy Regulatory Commission, “promises a lot more protective mechanisms,” he said. (See FERC OKs New Reliability Standards)
President Obama’s executive order, issued in February, was helpful in providing industry increased access to information, he said. “Not all information needs to be classified as high as it is.”
The Illinois Department of Commerce and Economic Opportunity took coal-education material off its website after objections that it was unduly pro-coal. The website sections, intended to educate children about energy, sparked a grassroots campaign demanding that the pages be taken down.
(Source: IL Dept. of Commerce & Economic Opportunity)
An eastern Kentucky economic development organization recommended some coal severance tax funds be devoted to a program to diversify the regional economy. But many local needs and dwindling revenue from the tax present tough decisions for the area’s policy makers. Eastern Kentucky has lost more than 5,700 coal jobs in the last two years.
PPL’s two Kentucky utilities have proposed building a 700 MW combined-cycle plant and a 10 MW solar facility to help replace retiring coal generation. The new projects would make the Louisville Gas and Electric-Kentucky Utilities portfolio 59% coal, 40% gas and 1% renewables.
Baltimore Gas & Electric must try harder to reach customers who have not responded to efforts to switch them to smart meters, the Public Service Commission said, rejecting for now the utility’s suggestion to call these customers meter “opt-outs.” BG&E also may not terminate their service for non-response, the PSC ruled.
Michigan could get 40% of its energy from renewables by 2035, and do so at half the cost assumed when the state enacted its renewable portfolio standard in 2008, a renewable energy trade group said. The Michigan Energy Innovation Business Council made its comments in response to a draft state report that predicted the state could get 30% of its electricity needs from renewable sources by 2035.
American Transmission Co. filed for state approval of a 60-mile 138 kV line to improve reliability of Michigan’s Upper Peninsula grid. The line, which would cost up to $132 million, is part of a larger Bay Lake project. ATC plans to spend up to $3.6 billion over the next decade in Michigan, Wisconsin and neighboring states.
Newly-elected Sen. Cory Booker, who won the seat made vacant by the death of New Jersey Democratic Sen. Frank Lautenberg, may be assigned to the Environment and Public Works Committee. Lautenberg was an active member of the panel, and Booker has been engaged with climate change issues in New Jersey.
Natural gas is a major player right now, but “there is no doubt coal needs to continue to play a major role in our future generation mix,” PUC Chairman Todd Snitchler told a state House committee. He also expressed confidence in advanced coal technologies.
AEP CEO Nick Akins sees coal as a diminishing part of the utility’s portfolio. The company’s future is “natural gas, energy efficiency, smart-grid activities and renewables,” he told a Columbus Metropolitan Club program.
PPL asked the Public Utility Commission to add another new line item to its customers’ bills: a fee that would help it recoup its costs for severe weather and expenses related to the $60 million blow dealt the company by Hurricane Sandy in 2012. The utility has just begun to collect a distribution improvement charge, a first in the state, and the new charge, if approved, would also be a first.
The Public Utility Commission refused to disclose details of its $60,000 settlement with PPL that resolved allegations that the company improperly transferred a repair crew from a high-priority outage to work on a low-priority outage after a freak snowstorm in October 2011.
The PUC denied a public records request by The Morning Call to review the letter from an anonymous tipster that launched regulators’ investigation. The PUC said its decision was necessary to protect the identity of the whistleblower. The agency also refused to identify the locations involved in the incident.
The Public Utility Commission approved settlements with IDT Energy and AP Gas & Electric on complaints of “slamming” and other illegal practices. The companies will pay civil settlements and take steps to comply with the state’s regulations. They admitted no wrongdoing.
PennFuture, an environmental group, criticized state officials for refusing to consider raising Pennsylvania’s alternative energy standard above the current target of 8% by 2021. “While other states in the region and around the country recognize the multiple benefits of renewable energy and have increased the requirements in their state portfolios, [the Department of Environmental Protection] is telling us upfront that they won’t consider the idea of increasing renewable energy in Pennsylvania,” the group said.
Dominion Virginia Power proposed lowering average customer bills 3.3% because of the unexpectedly lower cost of fuel. The fuel adjustment, which Dominion wants to make earlier than scheduled, would cut an average residential bill about $3.70. Overall rates would be about where they were five years ago, the company said.
Generation owners that do not qualify for a connection to the PJMNet private communication network would be able to purchase as many as five under a proposal approved by the Operating Committee.
PJM currently pays for at least one PJMNet connection for each transmission owner considered important to system reliability and for generation owners with resources of at least 100 MW. Entities that do not have a PJMNet link connect to PJM by Internet SCADA, which is less reliable.
The committee approved a proposal that would let smaller generating members, and those that already have a PJMNet connection, buy up to five connections. Members rejected a proposal to allow smaller generators to buy only one connection and another that would have required all members to buy their first connection.
PJM says the monthly cost for a non-redundant connection will be about $2,600. Installation will cost about $12,000 or $22,000, depending on the type of protocol used. Redundant connections would cost more.
The Operating Committee last week endorsed changes to Manuals 3, 10 and 14D.
Manual 3: Transmission Operations – Adds language regarding approval of emergency rating changes; added applicability for individual generators greater than 20 MVA; clarified reference to voltage coordination; revised outdated references.
Manual 10: Pre-Scheduling Operations – Annual Review. Minor updates for clarity; added references to forecasted planned outages and reporting outages on synchronous condensers.
Manual 14D: Generator Operational Requirements – Changes made at RFC request, and for consistency. Includes changes to reactive capability testing; replaces outdated references; requires generators operating or scheduled for PJM to operate to notify PJM prior to attempting a restart following a trip or failure to start.
